Systems for generating geothermal power in an organic rankine cycle operation during hydrocarbon production based on wellhead fluid temperature

ABSTRACT

Systems and methods for generating and a controller for controlling generation of geothermal power in an organic Rankine cycle (ORC) operation in the vicinity of a wellhead during hydrocarbon production to thereby supply electrical power to one or more of in-field operational equipment, a grid power structure, and an energy storage device. In an embodiment, during hydrocarbon production, a temperature of a flow of wellhead fluid from the wellhead or working fluid may be determined. If the temperature is above a vaporous phase change threshold of the working fluid, heat exchanger valves may be opened to divert flow of wellhead fluid to heat exchangers to facilitate heat transfer from the flow of wellhead fluid to working fluid through the heat exchangers, thereby to cause the working fluid to change from a liquid to vapor, the vapor to cause a generator to generate electrical power via rotation of an expander.

CROSS REFERENCE TO RELATED APPLICATIONS

This application is a continuation of U.S. application Ser. No. 18/149,316, filed Jan. 3, 2023, titled “SYSTEMS FOR GENERATING GEOTHERMAL POWER IN AN ORGANIC RANKINE CYCLE OPERATION DURING HYDROCARBON PRODUCTION BASED ON WELLHEAD FLUID TEMPERATURE”, which is a continuation of U.S. application Ser. No. 17/650,811, filed Feb. 11, 2022, titled “SYSTEMS FOR GENERATING GEOTHERMAL POWER IN AN ORGANIC RANKINE CYCLE OPERATION DURING HYDROCARBON PRODUCTION BASED ON WELLHEAD FLUID TEMPERATURE”, now U.S. Pat. No. 11,578,706, issued Feb. 14, 2023, which is a continuation of U.S. application Ser. No. 17/305,298, filed Jul. 2, 2021, titled “SYSTEMS FOR GENERATING GEOTHERMAL POWER IN AN ORGANIC RANKINE CYCLE OPERATION DURING HYDROCARBON PRODUCTION BASED ON WELLHEAD FLUID TEMPERATURE”, now U.S. Pat. No. 11,280,322, issued Mar. 22, 2022, which claims priority to and the benefit of U.S. Provisional Application No. 63/200,908, filed Apr. 2, 2021, titled “SYSTEMS AND METHODS FOR GENERATING GEOTHERMAL POWER DURING HYDROCARBON PRODUCTION,” the entire disclosures of all of which are incorporated herein by reference.

FIELD OF DISCLOSURE

Embodiments of this disclosure relate to generating geothermal power during hydrocarbon production, and more particularly, to systems and methods for generating and controllers for controlling generation of geothermal power in an organic Rankine cycle (ORC) operation in the vicinity of a wellhead during hydrocarbon production to thereby supply electrical power to one or more of in-field operational equipment, a grid power structure, and an energy storage device.

BACKGROUND

Typically, geothermal generators include a working fluid loop that flows to varying depths underground, such that underground heat causes the working fluid in the loop to change phases from a liquid to a vapor. The vaporous working fluid may then flow to a gas expander, causing the gas expander to rotate. The rotation of the gas expander may cause a generator to generate electrical power. The vaporous working fluid may then flow to a condenser or heat sink. The condenser or heat sink may cool the working fluid, causing the working fluid to change phase from the vapor to the liquid. The working fluid may circulate through the loop in such a continuous manner, thus the geothermal generator may generate electrical power.

Heat exchangers within geothermal generators are not built to withstand high pressures. Typically, the working fluid does not flow through the loop under high pressure. Further, rather than including heat exchangers, typically, geothermal generators utilize geothermal heat from varying depths underground, the heat being transferred to the working fluid. For example, a geothermal generator may simply include a conduit or pipe buried deep underground. As working fluid flows through the conduit or pipe, the heat at such depths causes the working fluid to change to a vapor and the vapor may flow up to the gas expander. As the vapor is cooled, the vapor flows back underground, the cycle repeating. While old or non-producing wells have been utilized for geothermal power generation, no such solution is known to exist for generating geothermal power at a well during hydrocarbon production.

Accordingly, Applicants have recognized a need for systems and methods to generate geothermal power in an organic Rankine cycle (ORC) operation in the vicinity of a wellhead during hydrocarbon production to thereby supply electrical power to one or more of in-field operational equipment, a grid power structure, and an energy storage device. The present disclosure is directed to embodiments of such systems and methods

SUMMARY

The present disclosure is generally directed to systems and methods for generating and controlling generation of geothermal power in an organic Rankine cycle (ORC) operation in the vicinity of a wellhead during hydrocarbon production to thereby supply electrical power to one or more of in-field operational equipment, a grid power structure, and an energy storage device. The wellhead may produce a wellhead fluid. The wellhead fluid, as it exits the wellhead, may be under high-pressure and at a high temperature. The wellhead fluid's temperature may be determined, as well as the pressure, and based on such determinations, one or more heat exchanger valves may be actuated to partially open or completely open, thereby diverting a portion or all of the flow of wellhead fluid to the heat exchanger. The heat exchanger may be a high-pressure heat exchanger configured to withstand the high-pressure of the wellhead fluid from a wellhead. The heat exchanger may indirectly transfer heat from the flow of the wellhead fluid to the flow of a working fluid. As heat is transferred from the flow of the wellhead fluid to the flow of a working fluid, such a heat transfer may cause the working fluid to change phases from a liquid to a vapor. The vaporous working fluid may then flow through an ORC unit to cause a generator to generate electrical power via rotation of a gas expander of the ORC unit. Such an operation may be defined as or may be an ORC operation or process. The ORC unit may be an off-the-shelf unit, while the high-pressure heat exchanger may be a stand-alone component or device. In another embodiment, the ORC unit may be a high-pressure ORC unit and may include the high-pressure heat exchanger apparatus.

Accordingly, an embodiment of the disclosure is directed to a system for generating geothermal power in an organic Rankin cycle (ORC) operation in the vicinity of a wellhead during hydrocarbon production to thereby supply electrical power to one or more of in-field equipment, a grid power structure, and energy storage devices. The system may include a first temperature sensor to provide a first temperature. The first temperature may be defined by a temperature of wellhead fluid flowing from one or more wellheads. The system may include a heat exchange valve to divert flow of wellhead fluid from the one or more wellheads based on the first temperature. The system may include a high-pressure heat exchanger including a first fluid path to accept and output the flow of wellhead fluid from the heat exchange valve and a second fluid path to accept and output the flow of an organic working fluid, the high-pressure heat exchanger to indirectly transfer heat from the flow of wellhead fluid to the flow of the organic working fluid to cause the organic working fluid to change phases from a liquid to a vapor. The system may include an ORC unit. The ORC unit may include a generator, a gas expander, a condenser, a pump, and a partial loop for the flow of the organic working fluid. The partial loop may be defined by a fluid path through the condenser, generator, and pump, the partial loop forming a complete loop when connected to the fluid path of the high-pressure heat exchanger, the flow of the organic working fluid, as a vapor, to cause the generator to generate electrical power via rotation of a gas expander as defined by an ORC operation, the condenser to cool the flow of the organic working fluid, the cooling to cause the organic working fluid to change phases from the vapor to the liquid, the pump to transport the liquid state organic working fluid from the condenser for heating.

In another embodiment, the system may include a first wellhead fluid valve to adjust flow of wellhead fluid from the one or more wellheads based on the diversion of the flow of wellhead fluid to the heat exchange valve. The system may include a choke valve to accept and to reduce the pressure of the flow of wellhead fluid from the high-pressure heat exchanger thereby reducing the temperature of the flow of wellhead fluid. The system may include a condenser valve to divert flow of wellhead fluid from the choke valve based on whether the heat exchange valve is open. The system may include a second wellhead fluid valve to control flow of wellhead fluid from the choke valve based on a percentage that the condenser valve is open.

The system may include another one or more ORC units connected to the high-pressure heat exchanger. The ORC unit may include a working fluid reservoir to store organic working fluid flowing from the condenser. The first fluid path of the high-pressure heat exchanger may be configured to withstand corrosion caused by the wellhead fluid. The high-pressure heat exchanger may include vibration induction device to reduce scaling caused by the flow of the wellhead fluid.

Another embodiment is directed to a system for generating geothermal power in the vicinity of a wellhead during hydrocarbon production to thereby supply electrical power to one or more of in-field equipment, a grid power structure, and energy storage devices. The system may include a first pipe connected to and in fluid communication with the wellhead. The first pipe may be configured to transport wellhead fluid under high-pressure. The system may include a first temperature sensor connected to the first pipe. The first temperature sensor may provide a first temperature. The first temperature may be defined by a temperature of wellhead fluid flowing through the first pipe. The system may include a first wellhead fluid valve having a first end and second end. The first end of the first wellhead fluid valve may be connected to and in fluid communication with the first pipe. The first wellhead fluid valve may control flow of wellhead fluid based on the first temperature. The system may include a heat exchange valve connected to and in fluid communication with the first pipe. The heat exchange valve may control flow of wellhead fluid based on the first temperature. The system may include a high-pressure heat exchanger to accept the flow of wellhead fluid when the heat exchange valve is open. The high-pressure heat exchanger may include a first opening and a second opening connected via a first fluidic path and a third opening and a fourth opening connected via a second fluidic path, the first fluidic path and the second fluidic path to facilitate heat transfer from the flow of wellhead fluid to an organic working fluid, the transfer of heat from the wellhead fluid to the organic working fluid to cause the organic working fluid to changes phases from a liquid to a vapor, the flow of wellhead fluid flowing into the first opening of the high-pressure heat exchanger from the heat exchange valve through the first fluidic path and to the second opening of the high-pressure heat exchanger, and a flow of the organic working fluid flowing into the third opening through the second fluidic path and out of the fourth opening. The system may include a second pipe connected to and in fluid communication with the second end of the first wellhead fluid valve and connected to and in fluid communication with the second opening of the high-pressure heat exchanger. The system may include a choke valve connected to and in fluid communication with the second pipe to reduce the pressure of the flow of wellhead fluid thereby reducing the temperature of the wellhead fluid. The system may include a second wellhead fluid valve having a first end and second end, the first end of the second wellhead fluid valve connected to and in fluid communication with the choke valve. The second wellhead fluid valve may control flow of wellhead fluid based on whether the first wellhead fluid valve is open. The system may include a condenser valve connected to and in fluid communication with the choke valve. The condenser valve may control flow of wellhead fluid based on whether the first wellhead fluid valve is open. The system may include a generator connected to and in fluid communication with the fourth opening of the high-pressure heat exchanger. The organic working fluid may flow from the fourth opening to the generator and causing the generator to generate electrical power via rotation of a vapor expander as defined by an ORC operation. The system may include a condenser. The condenser may include a first opening and second opening connected via a first fluidic condenser path and a third opening and fourth opening connected via a second fluidic condenser path, the first opening connected to the condenser valve, the second opening connected to an output pipe, and the third opening connected to the expander to receive the organic working fluid, the first fluidic condenser path and the second fluidic condenser path to facilitate heat transfer from the organic working fluid to the flow of wellhead fluid. The system may include a pump connected to the fourth opening of the condenser to pump the organic working fluid from the condenser to the third opening of the high-pressure heat exchanger.

In another embodiment, the organic working fluid may include one of pentafluoropropane, carbon dioxide, ammonia and water mixtures, tetrafluoroethane, isobutene, propane, pentane, perfluorocarbons, and other hydrocarbons. The generator may include a rotation mechanism, a stator, and rotor, the rotor connected to the rotation mechanism, the rotor to rotate as the rotation mechanism spins via the flow of organic working fluid. The rotation mechanism may include one of a turbine expander, a positive displacement expander, or a twin-screw expander. The rotation mechanism may connect to the rotor via one of a transmission and gearbox.

In another embodiment, when the heat exchanger valve is opened, a portion of the flow of wellhead fluid may be diverted from the first wellhead fluid valve.

In another embodiment, the organic working fluid may change phase from liquid to vapor when the wellhead fluid is at a temperature from greater than or equal to about 50 degrees Celsius. After the organic working fluid flows through the expander, the organic working fluid may flow through a regenerator and, after the working fluid flows through the condenser, the organic working fluid may flow through the regenerator. The regenerator may pre-heat the organic working fluid from the condenser via heat of the organic working fluid from the generator.

In an embodiment, the high-pressure heat exchanger may be configured to withstand pressures up to about 15,000 pounds per square inch (PSI). The high-pressure heat exchanger may include pressure relief valves. The pressure relief valves may open or release pressure in the event that the high-pressure heat exchanger exhibits a pressure exceeding a maximum pressure rating of the high-pressure heat exchanger.

In an embodiment, the choke valve may reduce the pressure of the flow of wellhead fluid to less than or equal to about 1,500 PSI. The reduction of pressure of the flow of wellhead fluid may reduce the temperature of the wellhead fluid to less than or equal to about 50 degrees Celsius.

The wellhead fluid may include one of a liquid and a gas. The wellhead fluid may include hydrocarbons. The wellhead fluid may further include a mixture of the hydrocarbons and one or more of water and other chemical residuals.

In another embodiment, the organic working fluid may be heated in the heat exchanger to the point of evaporation of the organic working fluid. The organic working fluid may be heated in the heat exchanger to saturation temperature under high-pressure. The working fluid may include a mixture of two or more fluids, each of the two or more fluids including different vaporous phase change points and different condensation points.

Another embodiment is directed to a system to generate geothermal power in the vicinity of one or more wellheads during hydrocarbon production to thereby supply electrical power to one or more of in-field operational equipment, a grid power structure, and energy storage devices. The system may include one or more wellheads. The system may include one or more ORC units. The system may include one or more high-pressure heat exchangers positioned to connect to piping at the one or more wellheads and to the one or more ORC units so that when one of the one or more ORC units is positioned at one of the one or more wellheads with one of the one or more high-pressure heat exchangers, the one or more ORC units generate geothermal power during hydrocarbon production at the one of the one or more wellheads, the geothermal power supplied to equipment at each of the one or more wellheads and excess geothermal power supplied to a grid. The one or more ORC units at one or more wellheads may connect to an electrical power grid via one or more transformer.

Still other aspects and advantages of these embodiments and other embodiments, are discussed in detail herein. Moreover, it is to be understood that both the foregoing information and the following detailed description provide merely illustrative examples of various aspects and embodiments, and are intended to provide an overview or framework for understanding the nature and character of the claimed aspects and embodiments. Accordingly, these and other objects, along with advantages and features of the present invention herein disclosed, will become apparent through reference to the following description and the accompanying drawings. Furthermore, it is to be understood that the features of the various embodiments described herein are not mutually exclusive and may exist in various combinations and permutations.

BRIEF DESCRIPTION OF DRAWINGS

These and other features, aspects, and advantages of the disclosure will become better understood with regard to the following descriptions, claims, and accompanying drawings. It is to be noted, however, that the drawings illustrate only several embodiments of the disclosure and, therefore, are not to be considered limiting of the scope of the disclosure.

FIG. 1A and FIG. 1B are schematic top-down perspectives of novel implementations of a geothermal power generation enabled well, according to one or more embodiment of the disclosure.

FIG. 2A, FIG. 2B, FIG. 2C, FIG. 2D, FIG. 2E, FIG. 2F, FIG. 2G, and FIG. 2H are block diagrams illustrating novel implementations of a geothermal power generation enabled well to provide electrical power to one or more of in-field equipment, equipment at other wells, energy storage devices, and the grid power structure, according to one or more embodiment of the disclosure.

FIG. 3A and FIG. 3B are block diagrams illustrating other novel implementations of a geothermal power generation enabled well to provide electrical power to one or more of in-field equipment, equipment at other wells, energy storage devices, and the grid power structure, according to one or more embodiment of the disclosure.

FIG. 4A and FIG. 4B are simplified diagrams illustrating a control system for managing geothermal power production at a well, according to one or more embodiment of the disclosure.

FIG. 5 is a flow diagram of geothermal power generation in which, when a wellhead fluid is at or above a vaporous phase change temperature, heat exchanger valves may be opened to allow wellhead fluid to flow therethrough, thereby facilitating heating of a working fluid for use in an organic Rankine cycle (ORC) unit, according to one or more embodiment of the disclosure.

FIG. 6 is another flow diagram of geothermal power generation in which, when a wellhead fluid is at or above a vaporous phase change temperature, heat exchanger valves may be opened to allow wellhead fluid to flow therethrough, thereby facilitating heating of a working fluid for use in a ORC unit, according to one or more embodiment of the disclosure.

FIG. 7A is a flow diagram of geothermal power generation in which, when an ORC fluid is at or above a vaporous phase change temperature, heat exchanger valves may remain open to allow wellhead fluid to flow therethrough, thereby facilitating heating of a working fluid for use in an ORC unit, according to one or more embodiment of the disclosure.

FIG. 7B is another flow diagram of geothermal power generation in which, when an ORC fluid is at or above a vaporous phase change temperature, heat exchanger valves may remain open to allow wellhead fluid to flow therethrough, thereby facilitating heating of a working fluid for use in an ORC unit, according to one or more embodiment of the disclosure.

FIG. 8 is a flow diagram of geothermal power generation in which a working fluid flow is determined based on a preselected electrical power output threshold, according to one or more embodiment of the disclosure.

FIG. 9A, FIG. 9B, FIG. 9C, FIG. 9D, FIG. 9E, FIG. 9F, and FIG. 9G are block diagrams illustrating novel implementations of one or more geothermal power generation enabled wells to provide electrical power to one or more of in-field equipment, equipment at one of the other wells, energy storage devices, and the grid power structure, according to one or more embodiment of the disclosure.

DETAILED DESCRIPTION

So that the manner in which the features and advantages of the embodiments of the systems and methods disclosed herein, as well as others that will become apparent, may be understood in more detail, a more particular description of embodiments of systems and methods briefly summarized above may be had by reference to the following detailed description of embodiments thereof, in which one or more are further illustrated in the appended drawings, which form a part of this specification. It is to be noted, however, that the drawings illustrate only various embodiments of the systems and methods disclosed herein and are therefore not to be considered limiting of the scope of the systems and methods disclosed herein as it may include other effective embodiments as well.

The present disclosure is directed to systems and methods for generating geothermal power in an organic Rankine cycle (ORC) operation in the vicinity of a wellhead during hydrocarbon production to thereby supply electrical power to one or more of in-field equipment or operational equipment, a grid power structure, other equipment, and an energy storage device. Wellhead fluids flowing from a wellhead at a well are typically under high-pressure. In-field equipment at the well is not rated for such high pressures. Prior to further processing or transport, the pressure of the flow of the wellhead fluid may be reduced, e.g., from 15,000 PSI to 200 PSI, from 10,000 PSI to 200 PSI, from 2,000 PSI to 200 PSI, or any other range from 20,000 PSI to 100 PSI, based on the pressure rating of the in-field equipment at the well. As the wellhead fluid flows from the wellhead, the temperature of the flow of the wellhead fluid may be at a high temperature, at least partially due to the high pressure of the flow of the wellhead fluid. As the pressure is reduced, the wellhead fluid temperature may also be reduced, as result of the pressure drop. Typically, the heat of the flow of wellhead fluid from the wellhead is not utilized and may be considered heat waste.

Geothermal power generators typically use a looping pipe or pipeline buried at depths with sufficient temperature to allow a working fluid to change phase from liquid to vapor. As the working fluid changes phase from a liquid to a vaporous state, the vaporous state working fluid may flow up the pipe or pipeline to a gas expander. The vaporous state working fluid may flow through and cause the gas expander to rotate. The rotation of the gas expander may cause a generator to generate electrical power, as will be described below. The vaporous state working fluid may flow through the gas expander to a heat sink, condenser, or other cooling apparatus. The heat sink, condenser, or other cooling apparatus may cool the working fluid thereby causing the working fluid to change phases from a vapor to a liquid. Heat exchangers of typical geothermal generators are not rated for high-pressure operations and usually geothermal generators obtain heat from varying underground depths.

In the present disclosure, a high-pressure heat exchanger may be placed or disposed at the well and/or in the vicinity of one or more wellheads. The high-pressure heat exchanger may be connected to the wellhead and may accept a high temperature or heated flow of wellhead fluid. A working fluid may flow through the heat exchanger. As the wellhead fluid and working fluid flows through the high-pressure heat exchanger, the high-pressure heat exchanger may facilitate transfer of heat from the wellhead fluid to the working fluid. A heat exchanger may include two fluidic paths, one for a heated fluid and another for a cool fluid. The fluidic paths may be in close proximity, allowing heat to transfer from the heated fluid to the cool fluid. The fluidic paths may be loops, coils, densely packed piping, tubes, chambers, some other type of path to allow for fluid to flow therethrough, and/or a combination thereof, as will be understood by those skilled in the art. As fluids flow through the heat exchanger, the cool liquid's temperature may increase, while the heated liquid's temperature may decrease.

Additionally, a geothermal generator unit or ORC unit may be disposed, positioned, or placed at the wellhead. The geothermal generator unit or ORC unit may directly connect to the high-pressure heat exchanger, include the high-pressure heat exchanger, or may connect to the high-pressure heat exchanger via an intermediary heat exchanger. As the hot wellhead fluid heats the working fluid, either via direct connection or through an intermediary heat exchanger, the working fluid may change phases from a liquid to a vapor. In such examples, the working fluid utilized may be chosen based on a low boiling point and/or high condensing point. The vaporous state working fluid may flow through the geothermal generator unit or ORC unit to a generator, e.g., a gas expander and generator. The vaporous state working fluid may then flow to a condenser or heat sink, thereby changing state from the vapor to the liquid. Finally, the liquid may be pumped back to the high-pressure heat exchanger. Such a cycle, process, or operation may be considered a Rankine cycle or ORC.

Such systems may include various components, devices, or apparatuses, such as temperature sensors, pressure sensors or transducers, flow meters, control valves, smart valves, valves actuated via control signal, controllers, a master or supervisory controller, other computing devices, computing systems, user interfaces, in-field equipment, and/or other equipment. The controller may monitor and adjust various aspects of the system to ensure that hydrocarbon production continues at a specified rate, that downtime is limited or negligible, and that electrical power is generated efficiently, optimally, economically, and/or to meet or exceed a preselected electrical power output threshold.

FIGS. 1A and 1B are schematic top-down perspectives of novel implementations of a geothermal power generation enabled well, according to one or more embodiment of the disclosure. As illustrated in FIG. 1A, a well 100 may include various components or equipment, also referred to as in-field equipment. Such in-field equipment may include fracturing equipment, field compressors, pump stations, artificial lift equipment, drilling rigs, data vans, and/or any other equipment utilized or used at a well 100. For example, the well 100 may include one or more pumpjacks 108, one or more wellhead compressors 110, various other pumps, various valves, and/or other equipment that may use electrical power or other type of power to operate. To generate power from otherwise wasted heat, the well 100 may additionally include a high-pressure heat exchanger 104, one or more geothermal generators, one or more ORC units 106, a high-pressure geothermal generator, a high-pressure ORC unit, and/or some combination thereof. As wellhead fluid flows from one of the one or more wellheads 102, a portion of the flow of wellhead fluid or all of the flow of wellhead fluid may flow through the high-pressure heat exchanger 104, high-pressure geothermal generator, a high-pressure ORC unit, or some combination thereof. As the hot and high-pressure wellhead fluid flows through, for example, the high-pressure heat exchanger 104, the high-pressure heat exchanger 104 may facilitate a transfer of heat from the wellhead fluid to a working fluid flowing through the high-pressure heat exchanger 104. In other words, the wellhead fluid may heat the working fluid. Such a heat transfer may cause the working fluid to change phases from a liquid to a vapor. The vaporous state working fluid may flow from the high-pressure heat exchanger to the one or more ORC units 106. The one or more ORC units 106 may then generate power using the vaporous state working fluid. The electrical power may be transferred to the in-field equipment at the well 100, to an energy storage device (e.g., if excess power is available), to equipment at other wells, to the grid or grid power structure (e.g., via a transformer 116 through power lines 118), or some combination thereof.

As illustrated in FIG. 1B, one or more wells 100A, 100B, 100C may be nearby or in close proximity to each of the other one or more wells 100A, 100B, 100C. Further, each of the one or more wells 100A, 100B, 100C may utilize different amounts of electrical power, in addition to generating different amounts of electrical power. As such, one well (e.g., well 100A, well 100B, and/or well 100C) of the one or more wells 100A, 100B, 100C may generate a surplus of electrical power or utilize electrical power from other sources. In an example, a controller may determine if a well (e.g., well 100A, well 100B, and/or well 100C) of the one or more wells 100A, 100B, 100C generates a surplus. If a surplus is generated, the controller may determine which, if any, of the other one or more wells 100A, 100B, 100C may have a deficit of electrical power. The controller may then transmit signals to equipment at the one or more wells 100A, 100B, 100C to enable electrical power transfer between the one or more wells 100A, 100B, 100C with excess and deficits, e.g., a well with a deficit may receive electrical power from a well with a surplus (see 120). In another example, the one or more wells 100A, 100B, 100C may include energy storage devices e.g., batteries, battery banks, or other solutions to store energy for short or long term time periods. The energy storage devices may be placed, disposed, or installed at one or more of the one or more wells 100A, 100B, 100C or at points in between the one or more wells 100A, 100B, 100C. As surplus electrical power is generated, that surplus electrical power may be transmitted and stored in the energy storage devices. The energy storage devices may be accessible by the in-field equipment of each of the one or more wells 100.

As illustrated in FIGS. 1A and 1B, the one or more wells 100A, 100B, 100C may include a high-pressure heat exchanger 104 and ORC units 106. In an example, the ORC units 106 may be modular and/or mobile. The ORC units 106 may be mounted to a vehicle, such as a truck or other vehicle type, or skid and transported to the well 100. Further, the high-pressure heat exchanger 104 may be modular and/or mobile. The high-pressure heat exchanger 104 may be mounted to a vehicle and/or skid. Upon arrival at one of the one or more wells 100A, 100B, 100C, the high-pressure heat exchanger 104 may be removed from the vehicle or the vehicle may be left on-site or at least while the one or more wells 100A, 100B, 100C are producing hydrocarbons. In an example, during hydrocarbon production, operation of the high-pressure heat exchanger 104 and ORC unit 106 may occur. After hydrocarbon production has ceased, none, some, or all of the equipment may be removed from the well 100. For example, the well 100 may be re-used for generating geothermal energy via a different method. In such examples the ORC units 106 and high-pressure heat exchanger 104 may remain on-site.

FIG. 2A, FIG. 2B, FIG. 2C, FIG. 2D, FIG. 2E, FIG. 2F, FIG. 2G, and FIG. 2H are block diagrams illustrating novel implementations of a geothermal power generation enabled well to provide electrical power to one or more of in-field equipment, equipment at other wells, energy storage devices, and the grid power structure, according to one or more embodiment of the disclosure. As illustrated in the FIGS. 2A through 2H, different embodiments may be utilized for geothermal power generation at the surface of a well during hydrocarbon production. As illustrated in FIG. 2A, a well 200 may include a wellhead 202. The wellhead 202 may produce a stream or flow of wellhead fluid. The wellhead fluid may flow from a first pipe 215. The first pipe 215 may include, at various positions along the length of the pipe 215, sensors, meters, transducers, and/or other devices to determine the characteristics of the wellhead fluid flowing through pipe 215. Further, sensors, meters, transducers and/or other devices may be included at various positions within the high-pressure heat exchanger 250 and/or ORC unit 203 to determine the characteristics of the working fluid or ORC fluid flowing through the high-pressure heat exchanger 250 and/or ORC unit 203. Based on the determined characteristics of the wellhead fluid, working fluid, and/or ORC fluid and/or characteristics of other aspects of the well 200, e.g., temperature, pressure, flow, power demand and/or power storage or transmission options and/or other factors, a first heat exchanger valve 208 connected to the first pipe 215 may be opened, e.g., partially opened or fully opened.

Further, when the first heat exchanger valve 208 is opened, a second heat exchanger valve 222 connected to a second pipe 217 may be opened, e.g., partially opened or fully opened. The second heat exchanger valve 222 may allow the flow of wellhead fluid to exit the high-pressure heat exchanger 250. Based on the opening of the first heat exchanger valve 208 and second heat exchanger valve 222, a first wellhead fluid valve 210 may be adjusted. Such adjustment may occur to ensure that the production of the wellhead 202 or the production of wellhead fluid from the wellhead 202 may not be impeded or slowed based on a diversion of the flow of the wellhead fluid to the high-pressure heat exchanger 250. Downstream of the first wellhead fluid valve 210, but prior to where the diverted portion of the flow of wellhead fluid is reintroduced to the primary or bypass wellhead fluid flow, a pressure sensor 212 may be disposed, e.g., the pressure sensor 212 may be disposed along pipe 217. In another example, rather than a pressure sensor 212, a flow meter may be disposed along pipe 217, e.g., a wellhead fluid flow meter and/or a downstream flow meter. The wellhead fluid flow meter may measure the flow rate of a fluid exiting the wellhead 202. A downstream flow meter may measure the flow rate of the wellhead fluid at a point downstream of the first wellhead fluid valve 210. Such a pressure sensor 212 or flow meter may be utilized to determine whether the flow of wellhead fluid is at a pressure or flow that does not impede hydrocarbon production. In an example, where the flow is impeded to a degree that the production of hydrocarbons may be inhibited, the first wellhead fluid valve 210 may be opened further, if the first wellhead fluid valve 210 is not already fully opened. If the first wellhead fluid valve 210 is fully opened, the first heat exchanger valve's 208 and second heat exchanger valve's 222 percent open may be adjusted. Other factors may be taken into account for such determinations, such as the pressure or flow from the high-pressure heat exchanger 250, the pressure or flow at the point of a choke valve located further downstream along the second pipe 217, a pressure rating for downstream equipment, and/or the temperature of the wellhead fluid within the high-pressure heat exchanger 250. Once the flow of wellhead fluid passes through the first wellhead fluid valve 210 and/or the second heat exchanger valve 222, the wellhead fluid may flow to in-field equipment 270 for further processing or transport.

Each of the valves described herein, e.g., first heat exchanger valve 208, second heat exchanger valve 222, first wellhead fluid valve 210, and other valves illustrated in the FIG. 2B through FIG. 9G, may be control valves, electrically actuated valves, pneumatic valves, or other valves suitable to receive signals and open and close under, potentially, high pressure. The valves may receive signals from a controller or other source and the signals may cause the valves to move to a partially or fully opened or closed position. The signal may indicate the position that the valve may be adjusted to, e.g., a position halfway open, a position a third of the way open, a position a particular degree open, or completely open, such positions to be understood as non-limiting examples. In such examples, as the valve receives the signal indicative of a position to adjust to, the valve may begin turning to the indicated position. Such an operation may take time, depending on the valve used. To ensure proper operation and prevent damage (e.g., damage to the high-pressure heat exchanger 250, such as when pressure of the wellhead fluid exceeds a pressure rating of the high-pressure heat exchanger 250), the valve may be configured to close in a specified period of time while high-pressure fluid flows therethrough. Such a configuration may be based on a torque value of the valve, e.g., a valve with a higher torque value may close faster than that of a control valve with a lower torque value. Such a specified period of time may be 5 seconds to 10 seconds, 5 seconds to 15 seconds, 5 seconds to 20 seconds, 10 seconds to 15 seconds, 10 seconds to 20 seconds, or 15 seconds to 20 seconds. For example, if a wellhead fluid flow exceeds a pressure of 15,000 PSI, the first heat exchanger valve 208 may close within 5 seconds of the pressure sensor 214 indicating the pressure exceeding 15,000 PSI. In other embodiments, the valves may either fully open or fully close, rather than open to positions in between. In yet other examples, the valves may be manually or physically opened by operators or technicians on-site.

As illustrated in FIG. 2A, pressure sensors 204, 212, 214, 222, 207 and/or temperature sensors 206, 216, 218, 226, 218 may be disposed at various points on or along different pipes, equipment, apparatuses, and/or devices at the well. Each sensor may provide information to adjust and/or control various aspects of the wellhead fluid flow. For example, pressure sensors 204, 212 may provide pressure measurements to determine whether a flow of wellhead fluid is not impeded in relation to hydrocarbon production targets. Pressure sensors 214, 220 may provide measurements to ensure that the flow of wellhead fluid through the high-pressure heat exchanger 250 is sufficient to facilitate heat transfer from the wellhead fluid to a working fluid in a ORC loop 221 and/or that the pressure within the high-pressure heat exchanger 250 does not exceed a pressure rating of the high-pressure heat exchanger 250. In another example, temperature sensor 206 may provide data to control flow of the wellhead fluid. For example, if the flow of wellhead fluid is at a temperature sufficient to cause the working fluid to exhibit a vaporous phase change, then the first heat exchanger valve 208 and second heat exchanger valve 222 may be opened. Further, temperature sensors 216, 218, 226, 248 may provide measurements to ensure that the temperatures within the heat exchanger, of the flow of wellhead fluid, and of the flow of working fluid, are above the thresholds or within a range of thresholds, e.g., above a vaporous phase change threshold. For example, rather than or in addition to using temperature of the wellhead fluid as measured by temperature sensor 206, the temperature of the working fluid as measured by temperature sensor 226 may be utilized to determine whether to maintain an open position of an already open first heat exchanger valve 208. In such examples, the first heat exchanger valve 208 may initially be fully or partially open, e.g., prior to flow of the wellhead fluid.

In another embodiment, in addition to the first heat exchanger valve 208 and second heat exchanger valve 222, the well 200 may include a first ORC unit valve 295 and a second ORC unit valve 296. Such ORC unit valves 295, 296 may be utilized to control flow of working fluid flowing into the ORC unit 203. Further the ORC unit valves 295, 296 may be utilized when more than one high-pressure heat exchanger 250 corresponding to one or more wellheads are connected to the ORC unit 203. The ORC unit valves 295, 296 may be utilized to optimize or to enable the ORC unit 203 to meet a preselected electrical power output threshold via the flow of working fluid from one or more high-pressure heat exchangers into the ORC unit 203, as will be understood by a person skilled in the art. The flow of working fluid may be adjusted to ensure that the ORC unit 203 produces an amount of electrical power greater than or equal to a preselected electrical power output threshold, based on various factors or operating conditions (e.g., temperature of wellhead fluid flow, temperature of working fluid flow, electrical output 236 of the ORC unit 203, electrical rating of the ORC unit 203, flow and/or pressure of the wellhead fluid, and/or flow and/or pressure of the working fluid). In some examples, the ORC unit valves 295, 296 may initially be fully open or at least partially open and as various factors or operating conditions are determined, then the ORC unit valves 295, 296 for one or more heat exchangers may be adjusted to enable the ORC unit 203 to meet a preselected electrical power output threshold, as will be understood by a person skilled in the art. The preselected electrical power output threshold may be set by a user or may be a predefined value generated by a controller (e.g., controller 272) based on various factors. The various factors may include an ORC unit electrical power rating or output rating or maximum potential temperature of the wellhead fluid and/or working fluid.

As shown, several pairs of sensors may be located adjacent to one another. In other examples, those positions, for example, the pressure sensor's 204 and the temperature sensor's 206 location, may be reversed. In yet another example, each one of the sensors may provide measurements for multiple aspects of the wellhead fluid, e.g., one sensor to provide a combination of flow, pressure, temperature, composition (e.g., amount of components in the wellhead fluid, such as water, hydrocarbons, other chemicals, proppant, etc.), density, or other aspect of the wellhead fluid or working fluid. Each sensor described above may be integrated in or within the pipes or conduits of each device or component, clamped on or over pipes or conduits, and or disposed in other ways, as will be understood by those skilled in the art. Further, the determinations, adjustments, and/or other operations described above may occur or may be performed by or in a controller.

As noted, a high-pressure heat exchanger 250 may be disposed, placed, or installed at a well. The high-pressure heat exchanger 250 may be disposed nearby or at a distance from the wellhead 202. The high-pressure heat exchanger 250 may be a modular and/or mobile apparatus. In such examples, the high-pressure heat exchanger 250 may be brought or moved to a well or site (e.g., via a vehicle, such as a truck), placed at the well or site during hydrocarbon production, and then moved to another well or site at the end of hydrocarbon production. The high-pressure heat exchanger 250 may be disposed on a skid, a trailer, a flatbed truck, inside a geothermal generator unit, or inside an ORC unit 203. Once brought to a well or site, the high-pressure heat exchanger 250 may be secured to the surface at the well. The high-pressure heat exchanger 250 may be configured to withstand pressures in excess of about 5,000 PSI, about 10,000 PSI, about 15,000 PSI, and/or greater. In an example, the high-pressure heat exchanger 250 may be a high-pressure shell and tube heat exchanger, a spiral plate or coil heat exchanger, a heliflow heat exchanger, or other heat exchanger configured to withstand high pressures. In another example, portions of the high-pressure heat exchanger 250 may be configured to withstand high-pressures. For example, if a shell and tube heat exchanger is utilized, the shell and/or tubes may be configured to withstand high-pressures.

In another embodiment, at least one fluidic path of the high-pressure heat exchanger 250 may be coated or otherwise configured to reduce or prevent corrosion. In such examples, a wellhead fluid may be corrosive. To prevent damage to the high-pressure heat exchanger 250 over a period of time, the fluid path for the wellhead fluid may be configured to withstand such corrosion by including a permanent, semi-permanent, or temporary anti-corrosive coating, an injection point for anti-corrosive chemical additive injections, and/or some combination thereof. Further, at least one fluid path of the high-pressure heat exchanger 250 may be comprised of an anti-corrosive material, e.g., anti-corrosive metals or polymers. As noted, the wellhead fluid may flow into the high-pressure heat exchanger 250 at a high pressure. As the high-pressure heat exchanger 250 may operate at high pressure, the high-pressure heat exchange may include pressure relief valves to prevent failures if pressure within the high-pressure heat exchanger 250 were to exceed the pressure rating of the high-pressure heat exchanger 250. Over time, wellhead fluid flowing through the high-pressure heat exchanger 250 may cause a buildup of deposits or scaling. To prevent scaling and/or other related issues, the high-pressure heat exchanger 250 may be injected with scaling inhibitors or other chemicals or may include vibration or radio frequency induction devices.

Once the high-pressure heat exchanger 250 facilitates heat transfer from the wellhead fluid to the working fluid, the working fluid may partially, substantially, or completely change phases from a liquid to a vapor, vaporous state, gas, or gaseous state. The vapor or gas may flow to the ORC unit 203 causing an expander to rotate. The rotation may cause a generator to generate electricity, as will be further described and as will be understood by those skilled in the art. The generated electricity may be provided as an electrical output 236. The electricity generated may be provided to in-field equipment, energy storage devices, equipment at other wells, or to a grid power structure. The working fluid in the high-pressure heat exchanger may be a working fluid to carry heat. Further, the working fluid of the high-pressure heat exchanger 250 may or may not exhibit a vaporous phase change. The working fluid may carry heat to another heat exchanger 205 of the ORC unit 203. As such, heat may be transferred from the wellhead fluid to the working fluid of the high-pressure heat exchanger 250 and heat may be transferred from the working fluid of the high-pressure heat exchanger 250 to the working fluid of the ORC unit 203.

In an example, the working fluid may be a fluid with a low boiling point and/or high condensation point. In other words, a working fluid may boil at lower than typical temperatures, while condensing at higher than typical temperatures. The working fluid may be an organic working fluid. The working fluid may be one or more of pentafluoropropane, carbon dioxide, ammonia and water mixtures, tetrafluoroethane, isobutene, propane, pentane, perfluorocarbons, other hydrocarbons, a zeotropic mixture of pentafluoropentane and cyclopentane, other zeotropic mixtures, and/or other fluids or fluid mixtures. The working fluid's boiling point and condensation point may be different depending on the pressure within the ORC loop 221, e.g., the higher the pressure, the lower the boiling point.

FIG. 2B illustrates an embodiment of the internal components of an ORC unit 203. FIG. 2B further illustrates several of the same components, equipment, or devices as FIG. 2A illustrates. As such, the numbers used to label FIG. 2B may be the same as those used in 2A, as those number correspond to the same component. The ORC unit 203 as noted may be a modular or mobile unit. As power demand increases, additional ORC units 203 may be added, installed, disposed, or placed at the well. The ORC units 203 may stack, connect, or integrate with each other ORC unit. In an example, the ORC unit 203 may be a modular single-pass ORC unit.

An ORC unit 203 may include a heat exchanger 205 or heater. Connections to the heat exchanger 205 or heater may pass through the exterior of the ORC unit 203. Thus, as an ORC unit 203 is brought or shipped to a well or other location, a user, technician, service person, or other person may connect pipes or hoses from a working fluid heat source (e.g., the high-pressure heat exchanger 250) to the connections on the ORC unit 203, allowing a heat source to facilitate phase change of a second working fluid in the ORC unit 203. In such examples, the working fluid flowing through ORC loop 221 may include water or other organic fluid exhibiting a higher vaporous phase change threshold than the working fluid of the ORC unit 203, to ensure proper heat transfer in heat exchanger 205. Further, the heat exchanger 205 may not be a high-pressure heat exchanger. In such examples, the high-pressure heat exchanger 250 allows for utilization of waste heat from high-pressure wellhead fluids. In another embodiment and as will be described, a high-pressure heat exchanger 250 may be included in the ORC unit 203.

In yet another embodiment, the high-pressure heat exchanger 250 may be considered an intermediary heat exchanger or another intermediary heat exchanger (e.g., intermediary heat exchanger 219) may be disposed between the high-pressure heat exchanger 250 and the ORC unit 203 (as illustrated in FIG. 2C and described below). The working fluid flowing through the high-pressure heat exchanger 250 may be sufficient to heat another working fluid of the ORC unit 203. The working fluid of such an intermediary heat exchanger may not physically flow through any of the equipment in the ORC unit 203, except for heat exchanger 205, thereby transferring heat from the working fluid in ORC loop 221 to an ORC working fluid in a loop defined by the fluid path through the heat exchanger 205, condenser 211, expander 232, working fluid reservoir 298, and/or pump 244.

The ORC unit 203 may further include pressure sensors 228, 238, 246 and temperature sensors 230, 240 to determine whether sufficient, efficient, and/or optimal heat transfer is occurring in the heat exchanger 205. A sensor or meter may further monitor electrical power produced via the expander 232 and generator 234. Further, the ORC unit 203 may include a condenser or heat sink 211 to transfer heat from the second working fluid or working fluid of the ORC unit 203. In other words, the condenser or heat sink 211 may cool the second working fluid or working fluid of the ORC unit 203 causing the second working fluid or working fluid of the ORC unit 203 to condense or change phases from vapor to liquid. The ORC unit 203 may also include a working fluid reservoir 298 to store an amount of working fluid, e.g., in a liquid state, to ensure continuous operation of the ORC unit 203. The liquid state working fluid, whether from the working fluid reservoir 298 or directly form the condenser/heat sink 211, may be pumped, via pump 244, back to the heat exchanger 205. Further, the pressure prior to and after pumping, e.g., as measured by the pressure sensors 238, 246, may be monitored to ensure that the working fluid remains at a ORC unit or working fluid loop pressure rating.

As illustrated in FIG. 2C, the well may include an intermediary heat exchanger 219. In such examples, an ORC unit 203 may not be configured for high-pressure heat exchange. As such, an intermediary heat exchanger 219 may be disposed nearby the high-pressure heat exchanger 250, nearby the ORC unit 203, or disposed at some other point in between to alleviate such issues. The intermediary heat exchanger 219 may include a working fluid, also referred to as an intermediary working fluid, to flow through the intermediary loop 223. The intermediary fluid may include water, a water and glycol mixture, or other organic fluid exhibiting a higher vaporous phase change threshold than the working fluid of the ORC unit 203. In an embodiment, the intermediary heat exchanger 219 may include sensors, meters, transducers and/or other devices at various positions throughout to determine characteristic of fluids flowing therein, similar to that of the high-pressure heat exchanger 250.

As illustrated in FIG. 2D, rather than utilizing an ORC unit 203 that may not withstand high pressure, a high-pressure ORC unit or an ORC unit with integrated high-pressure heat exchanger 250 may be utilized for geothermal power generation. In such examples, the components, equipment, and devices may be similar to those described above. In another example, such a system, as illustrated in FIG. 2D, may include a heat sink 236 utilizing a cooled flow of wellhead fluid to cool the flow of working fluid. In such examples, as the flow of wellhead fluid passes through a choke valve 252, the pressure of the flow of wellhead fluid may be reduced, e.g., for example, from about 15,000 PSI to about 1,500 PSI, from about 15,000 PSI to about 200 PSI, from about 15,000 PSI to about 100 PSI, about 15,000 PSI to about 50 PSI or lower, from about 10,000 PSI to about 200 PSI or lower, from about 5,000 PSI to about 200 PSI or lower, or from 15,000 PSI to lower than 200 PSI. In such examples, the temperature from a point prior to the choke valve 252 and after the choke valve 252, e.g., a temperature differential, may be about 100 degrees Celsius, about 75 degrees Celsius, about 50 degrees Celsius, about 40 degrees Celsius, about 30 degrees Celsius, and lower. For example, the temperature of the wellhead fluid prior to the choke valve 252 may be about 50 degrees and higher, while, after passing through the choke valve 252, the temperature, as measured by the temperature sensor 259, may be about 30 degrees Celsius, about 25 degrees Celsius, about 20 degrees Celsius, to about 0 degrees Celsius.

The system may include, as noted, a temperature sensor 259 and pressure sensor 257 to determine the temperature of the wellhead fluid after the choke valve 252. The system may include temperature sensor 240 to determine the temperature of the working fluid or ORC fluid exiting the heat sink 236 and temperature sensor 238 to determine the temperature of the working fluid or ORC fluid entering the heat sink 236. The pressure and/or temperature of the wellhead fluid may be used to determine whether the heat sink 236 may be utilized based on pressure rating of the heat sink 236 and/or a liquid phase change threshold of the working fluid. In other words, if the flow of wellhead fluid is at a temperature sufficient to cool the working fluid and/or below a pressure rating of the heat sink 236, the heat sink valve 254 may open to allow wellhead fluid to flow through the heat sink 236 to facilitate cooling of the working fluid. In another embodiment, the heat sink valve 254 may initially be fully or partially open. The temperature of the working fluid or ORC fluid may be measured as the fluid enters the heat sink 236 and exits the heat sink 236. If the temperature differential indicates that there is no change or an increase in temperature, based on the temperature of the working fluid or ORC fluid entering the heat sink 236 and then leaving the heat sink 236, then the heat sink valve 254 may be closed. Temperature sensors 238, 240, 256, 262, and pressure sensors 258, 260 may be disposed within the heat sink 236 to ensure that the temperature of the wellhead fluid is suitable for cooling the working fluid and that the pressure of wellhead fluid does not exceed the pressure rating of the heat sink 236.

FIG. 2D also illustrates two flow meters 277, 279 disposed prior to the first wellhead fluid valve 210 and first heat exchanger valve 208. Such flow meters may measure the flow of the wellhead fluid at the point where the meter is disposed. Utilizing flow measurements may allow for fine-tuning or adjustment of the open percentage or position of the valves included in the system. Such fine-tuning or adjustment may ensure that the production of hydrocarbons at the well is not impeded by the use of the high-pressure heat exchanger. Other flow meters may be disposed at various other points of the system, e.g., after the first wellhead fluid valve 210, prior to or after the choke valve 252, at a point after the heat sink 236, and/or at various other points in the system. As stated, these flow meter may be utilized to ensure proper flow wellhead fluid throughout the system. In an example, the sensors and/or meters disposed throughout the system may be temperature sensors, densitometers, density measuring sensors, pressure transducers, pressure sensors, flow meters, mass flow meters, Coriolis meters, spectrometer, other measurement sensors to determine a temperature, pressure, flow, composition, density, or other variable as will be understood by those skilled in the art, or some combination thereof. Further, the sensors and/or meters may be in fluid communication with a liquid to measure the temperature, pressure, or flow or may indirectly measure flow (e.g., an ultrasonic sensor). In other words, the sensors or meters may be a clamp-on device to measure flow indirectly (such as via ultrasound passed through the pipe to the liquid).

As illustrated in FIG. 2E, a controller 272 may be included at the well. The controller 272 may be utilized in any of the previous or following drawings. The controller 272 may include one or more controllers, a supervisory controller, and/or a master controller. The controller 272 may connect to all the equipment and devices shown, including additional equipment and devices not shown, and may transmit control signals, receive or request data or measurements, control pumps, monitor electricity generated, among other things (see 274). The controller 272 may, in another example, control a subset of the components shown. In another example, a controller may be included in an ORC unit (see 203 in FIGS. 2A through 2C). The controller 272 may connect to and control the controller in the ORC unit 203. The controller 272 may transmit signals to the various control valves to open and close the valves by determined amounts or percentages or fully open or close the valves. The controller 272 may further determine, via a meter or other device or sensor, an amount of electrical power generated or being generated by the generator 234 or ORC unit 203.

As illustrated in FIG. 2F, the system may include another heat sink 241, in the case that the cooling offered by the flow of wellhead fluid in heat sink 236 is not sufficient. In an example, the heat sink 241 may be a fin fan cooler, a heat exchanger, a condenser, any other type of heat sink, a sing-pass parallel flow heat exchanger, a 2-pass crossflow heat exchanger, a 2-pass countercurrent heat exchanger, or other type of apparatus. As illustrated in FIG. 2G, the system may include a regenerator 290. In such examples, the working fluid may flow through a first fluid path of the regenerator 290. After the working fluid is cooled by a primary heat sink (e.g., heat sink 236), the working fluid may flow back through another fluid path of the regenerator 290. As such, the heat from the first fluid path may pre-heat the working fluid, while the second fluid path may offer some level of cooling to the working fluid.

As illustrated in FIG. 2H, the system may include a gas expander 291. In an example, the gas expander 291 may be a turbine expander, positive displacement expander, scroll expander, screw expander, twin-screw expander, vane expander, piston expander, other volumetric expander, and/or any other expander suitable for an ORC operation or cycle. For example and as illustrated, the gas expander 291 may be a turbine expander. As gas flows through the turbine expander, a rotor 293 connected to the turbine expander may begin to turn, spin, or rotate. The rotor 293 may include an end with windings. The end with windings may correspond to a stator 294 including windings and a magnetic field. As the rotor 293 spins within the stator 294, electricity may be generated. Other generators may be utilized, as will be understood by those skilled in the art. The generator 293 may produce DC power, AC power, single phase power, or three phase power.

FIG. 3A and FIG. 3B are block diagrams illustrating other novel implementations of a geothermal power generation enabled well to provide electrical power to one or more of in-field equipment, equipment at other wells, energy storage devices, and the grid power structure, according to one or more embodiment of the disclosure. FIGS. 3A and 3B may represent a side-view perspective block diagram of a well and the components at the well. In an example, wellhead fluid may flow from underground 304. The wellhead fluid flow 308 may include hydrocarbons or a mixture of hydrocarbons and other fluids, e.g., water, chemicals, fluids leftover from fracturing operations, other residuals, and/or other fluids as will be understood by those skilled in the art. The wellhead fluid may flow from a wellbore.

As the wellhead fluid flows from the wellhead 306, the wellhead fluid may flow to the high-pressure heat exchanger, through a bypass pipe, and/or a combination thereof based on various factors or characteristics, e.g., wellhead fluid temperature and/or pressure and/or working fluid temperature. For example, if the wellhead fluid flow 308 is above a vaporous phase change threshold for a working fluid flow 310, then valve 332 may open, at least partially, to allow the wellhead fluid flow to the high pressure heat exchanger 312. In such examples, the wellhead fluid may continue to flow through the primary or bypass wellhead fluid pipe. As such, valve 330 may remain open, whether completely or at a certain percentage. From the high-pressure heat exchanger 312, the wellhead fluid may flow back to the primary or bypass wellhead fluid pipe, to a condenser 316 or other cooling apparatus, and/or a combination thereof. If the wellhead fluid is at a temperature to provide cooling to the working fluid flow 310, then valve 336 may open to allow wellhead fluid to flow therethrough. In such examples, the valve 334 may close to prevent wellhead fluid from flowing back. If the wellhead fluid is not at a temperature to allow for cooling of the working fluid flow 310, then valve 336 may close or remained closed and valve 334 may open or remain open. From the condenser 316 or the primary or bypass wellhead fluid pipe, the wellhead fluid may flow to in-field equipment 316, storage tanks, and/or other processing equipment at the well. The valves described above may be controlled via controller 320.

In another embodiment, rather than basing the opening and closing of valve 332 and/or valve 336 on wellhead fluid flow 308 temperature, the valve 332 and/or valve 336 may be opened or closed based on the temperature of the working fluid flow 310. For example, prior to activating the wellhead 306 (e.g., allowing wellhead fluid to flow or pumping wellhead fluid from the wellhead 306), valve 332 may be open, fully or partially. As the wellhead fluid flows through the high-pressure heat exchanger 312, the temperature of the working fluid flow 310 may be measured. Based on the working fluid flow 310 temperature, taken at continuously or at periodic intervals, and after a specified period of time, if the working fluid flow 310 does not reach a vaporous phase change temperature, then valve 332 may be closed. Further, such operations may be performed in conjunction with measuring wellhead fluid flow 308 and opening or closing valve 332 based on such measurements.

The wellhead fluid flowing through the high-pressure heat exchanger 312 may be at a temperature to facilitate heat transfer to a working fluid flow 310. The working fluid may further flow, as a vaporous state working fluid flow to an ORC expander/generator 314. The vaporous state working fluid may cause the ORC expander/generator 314 to generate electrical power to be utilized at equipment at the well (e.g., in-field equipment), energy storage device, or a grid power structure (via a transformer and power lines). The working fluid may then flow to a condenser 316 or other cooling apparatus. The condenser 316 or other cooling apparatus may facilitate cooling of the working fluid flow 310 via the wellhead fluid flow, air, another liquid, and/or other types of heat sinks or heat exchangers. The liquid state working fluid may then flow back to the high-pressure heat exchanger 312.

In another embodiment, the high-pressure heat exchanger 312 may connect to an ORC unit/module 340 or one or more ORC units or modules. The number of ORC units/modules may scale based on power to be utilized by in-field equipment, the amount or potential capacity of electricity generation at the well, and/or other factors. After production of hydrocarbons begins, additional ORC units/modules may be added at the well or existing ORC units/modules may be removed from the well.

FIG. 4A and FIG. 4B are simplified diagrams illustrating a control system for managing the geothermal power production at a well, according to one or more embodiment of the disclosure. A master controller 402 may manage the operations of geothermal power generation at a wellhead during hydrocarbon production. The master controller 402 may be one or more controllers, a supervisory controller, programmable logic controller (PLC), a computing device (such as a laptop, desktop computing device, and/or a server), an edge server, a cloud based computing device, and/or other suitable devices. The master controller 402 may be located at or near the well. The master controller 402 may be located remote from the well. The master controller 402, as noted, may be more than one controller. In such cases, the master controller 402 may be located near or at various wells and/or at other off-site locations. The master controller 402 may include a processor 404, or one or more processors, and memory 406. The memory 406 may include instructions. In an example, the memory 406 may be a non-transitory machine-readable storage medium. As used herein, a “non-transitory machine-readable storage medium” may be any electronic, magnetic, optical, or other physical storage apparatus to contain or store information such as executable instructions, data, and the like. For example, any machine-readable storage medium described herein may be any of random access memory (RAM), volatile memory, non-volatile memory, flash memory, a storage drive (e.g., hard drive), a solid state drive, any type of storage disc, and the like, or a combination thereof. As noted, the memory 406 may store or include instructions executable by the processor 404. As used herein, a “processor” may include, for example one processor or multiple processors included in a single device or distributed across multiple computing devices. The processor may be at least one of a central processing unit (CPU), a semiconductor-based microprocessor, a graphics processing unit (GPU), a field-programmable gate array (FPGA) to retrieve and execute instructions, a real time processor (RTP), other electronic circuitry suitable for the retrieval and execution instructions stored on a machine-readable storage medium, or a combination thereof.

As used herein, “signal communication” refers to electric communication such as hard wiring two components together or wireless communication for remote monitoring and control/operation, as understood by those skilled in the art. For example, wireless communication may be Wi-Fi®, Bluetooth®, ZigBee, cellular wireless communication, satellite communication, or forms of near field communications. In addition, signal communication may include one or more intermediate controllers or relays disposed between elements that are in signal communication with one another.

The master controller 402 may include instructions 408 to measure temperature at various points or locations of the system (e.g., as illustrated in, for example, FIG. 2E). For example, temperature may be measured at a wellhead fluid temperature sensor 1 416, heat exchanger temperature sensors 418, wellhead fluid temperature sensor 2 420, condenser temperature sensors 422, and/or at various other points in the system 400. Other characteristics may be measured as well, such as flow, density, pressure, composition, or other characteristics related to the wellhead fluid and/or working fluid.

Utilizing the characteristics noted above, the master controller 402 may control various aspects of the system 400. For example, the master controller 402 may include flow control adjustment instructions 412. The system 400 may include one or more valves placed in various locations (For example, but not limited to, FIGS. 2A through 2H). Valves of the system 400 may include a wellhead fluid valve 1 426, heat exchanger valves 428, wellhead fluid valve 2 430, and condenser valves 432. As noted other valves may be included in the system and controlled by the master controller 402. The valves may operate to adjust flow based on a number of factors. Such factors may include temperature of a wellhead fluid, flow rate of the wellhead fluid, temperature of the working fluid, flow rate of the working fluid, pressure of the wellhead fluid at various points in the system, pressure of the working fluid at various points in the system, and/or some combination thereof.

In an example, the system 400 may include a user interface 436, e.g., such as a monitor, display, computing device, smartphones, tablets, and other similar devices as will be understood by those skilled in the art. A user may view data, enter thresholds or limits, monitor status of the equipment, and perform other various tasks in relation to the equipment at the well. For example, a specific flow rate may be set for hydrocarbon production. As a wellhead begins producing hydrocarbons (e.g., wellhead fluids begin flowing from a wellhead), the master controller 402 may monitor flow rate and compare the flow rate to the threshold either set by a user or pre-set in the master controller 402. If the master controller 402 determines that the heat exchanger valves 428 (e.g., via flow control adjustment instructions 412) should be open or are open and that the flow of wellhead fluid is higher or lower than the threshold, the master controller 402 may adjust the appropriate valves, e.g., wellhead fluid valve 426 and/or heat exchanger valves 428. The valve associated with the primary or bypass wellhead fluid pipe, e.g., wellhead fluid valve 426, may open or close by varying degrees based on such determinations.

In another example, the master controller 402 may include instructions 410 to control a pump for the ORC unit, e.g., working fluid pump 424. If heat exchanger valves 428 and condenser valves 432 are closed, the master controller 402 may transmit a signal to shut down or cease operation of the working fluid pump 424, if the working fluid pump 424 is operating. The master controller 402 may further transmit a signal, based on the heat exchanger valves 428 being open, to initiate or start operations of the working fluid pump 424. The working fluid pump 424 may be a fixed pressure pump or a variable frequency pump. The master controller 402 may further include instructions 414 to monitor the power output from an ORC unit or from expanders/generators 434 (e.g., expander/generator A 434A, expander/generator B 434B, and/or up to expander/generator N 434N). If the system 400 utilizes ORC units, the master controller 402 may determine the electrical power generated or output based on an output from, for example, ORC unit controller A 438A, ORC unit controller B 438B, and/or up to ORC unit controller N 438N. If the power output drops to an un-economical or unsustainable level or electrical power generation ceases completely while the heat exchanger valves 428 are open, the master controller 402 may transmit signals to close the heat exchanger valves 428. In another example, the master controller 402 may monitor electrical power output from other wells. The master controller 402 may monitor or meter the amount of electrical power being utilized at each of the wells and/or the amount of electrical power being generated at each of the wells. If an excess of electrical power exists, the master controller 402 may transmit signals causing the excess energy at any particular well to be stored in energy storage devices, transmitted to the grid, and/or transmitted to another well. If a deficit of electrical power exists, the master controller 402 may transmit a signal causing other wells to transmit electrical power to the well experiencing an electrical power deficit. In another example, the metered electrical power may be utilized for commercial trade, to determine a cost of the electricity generated, and/or for use in determining emissions or emission reductions through use of an alternate energy source (e.g., geothermal power).

In another example, the master controller 402 may include instructions to maximize energy output from an ORC unit. In such examples, the ORC unit may be connected to a plurality of high-pressure heat exchangers. Further, each of the high-pressure heat exchangers may connect to one or more wellheads. As a wellhead produces a wellhead fluid, the pressure and temperature of the wellhead fluid may vary, over time, as well as based on the location of the wellhead. The master controller 402 may determine the temperature of the wellhead fluid at each high-pressure heat exchanger and/or the temperature of the working fluid in each high-pressure heat exchanger. Based on these determinations, the master controller 402 may open/close valves associated with one or more particular high-pressure heat exchangers to ensure the most efficient heat transfer. Further, the master controller 402 may determine the amount of electrical power output from the ORC unit. Based on a power rating of the ORC unit (e.g., the maximum power output the ORC unit is able to produce) and/or the amount of electrical power output from the ORC unit, the master controller 402 may adjust valves associated with the one or more particular high-pressure heat exchangers to thereby increase electrical power output. Additional ORC units may be utilized and electrical power output for each may be optimized or efficiently generated. The master controller 402 may determine, for each ORC unit, the optimal amount or efficient amount of heated working fluid flowing from each high-pressure heat exchanger to ensure the highest amount of electrical power possible is generated per ORC unit or that each ORC unit meets a preselected electrical power output threshold. In such examples, each ORC unit may be connected to each high-pressure heat exchanger and the master controller 402 may determine which set of valves to open/close based on such an optimization or electrical power output threshold.

In another example, the master controller 402 may include failover instructions or instructions to be executed to effectively reduce or prevent risk. The failover instructions may execute in the event of ORC unit and/or high-pressure heat exchanger failure or if an ORC unit and/or high-pressure heat exchanger experiences an issue requiring maintenance. For example, the ORC unit and/or high-pressure heat exchanger may have various sensors or meters. Such sensors or meters, when providing measurement to the master controller 402, may indicate a failure in the ORC unit and/or high-pressure heat exchanger. In another example, the master controller 402 may include pre-determined parameters that indicate failures. If the master controller 402 receives such indications, the master controller 402 may open, if not already open, the wellhead fluid valve 1 426 and wellhead fluid valve 2 430. After the wellhead fluid valve 1 426 and wellhead fluid valve 2 430 are opened, the master controller 402 may close the heat exchanger valves 428, the condenser valves 432, or any other valve associated with the flow of fluid to the ORC unit and/or high-pressure heat exchanger. In such examples, the master controller 402 may prevent further use of the ORC unit and/or high-pressure heat exchanger until the issue or failure indicated is resolved. Such a resolution may be indicated by a user via the user interface 436 or based on measurements from sensors and/or meters.

In another example, the master controller 402 may, as noted, determine an amount of electrical power output by an ORC unit. The master controller 402 may additionally determine different characteristics of the electrical power output. For example, the master controller 402 may monitor the output voltage and frequency. Further, the master controller 402 may include pre-set or predetermined thresholds, limits, or parameters in relation to the monitored characteristics of the electrical power output. Further still, the master controller 402 may connect to a breaker or switchgear. In the event that the master controller 402 detects that an ORC unit exceeds any of the thresholds, limits, and/or parameters, the master controller 402 may transmit a signal to the breaker or switchgear to break the circuit (e.g., the flow of electricity from the ORC unit to a source) and may shut down the ORC unit (e.g., closing valves preventing further flow to the ORC unit, as described above).

FIG. 5 is a flow diagram of geothermal power generation in which, when a wellhead fluid is at or above a vaporous phase change temperature threshold, heat exchanger valves may be opened to allow wellhead fluid to flow therethrough, thereby facilitating heating of a working fluid for use in a ORC unit, according to one or more embodiment of the disclosure. The method is detailed with reference to the master controller 402 and system 400 of FIGS. 4A and 4B. Unless otherwise specified, the actions of method 500 may be completed within the master controller 402. Specifically, method 500 may be included in one or more programs, protocols, or instructions loaded into the memory of the master controller 402 and executed on the processor or one or more processors of the master controller 402. The order in which the operations are described is not intended to be construed as a limitation, and any number of the described blocks may be combined in any order and/or in parallel to implement the methods.

At block 502, the master controller 402 may determine whether the wellhead is active. Such a determination may be made based on sensors located at or near the wellhead, e.g., a pressure sensor indicating a pressure or a flow meter indicating a flow of a wellhead fluid or hydrocarbon stream from the wellhead. In other examples, a user may indicate, via the user interface 436, that the wellhead is active. If the wellhead is not active, the master controller 402 may wait for a specified period of time and make such a determination after the period of time. In an example, the master controller 402 may continuously check for wellhead activity.

At block 504, in response to wellhead activity or during hydrocarbon production, the master controller 402 may determine a wellhead fluid temperature. The wellhead fluid temperature may be measured by a wellhead fluid temperature sensor 1 416 disposed at or near the wellhead. The wellhead fluid temperature sensor 1 416 may be disposed on or in a pipe. In an example, various other temperature sensors may be disposed at other points in the system 400, e.g., heat exchanger temperature sensor 418, wellhead fluid temperature sensor 2 420, condenser temperature sensor 422, and/or other temperature sensors. The temperature measurements provided by such sensors may be utilized by the master controller 402 to determine which valves to open or close.

At block 506, the master controller 402 may determine whether the wellhead fluid is at or above a vaporous phase change temperature threshold of a working fluid. In such examples, the vaporous phase change temperature may be based on the working fluid of the ORC unit. For example, for pentafluoropropane the vaporous phase change temperature or boiling point may be 15.14 degrees Celsius. In another example, or factors may be taken into account when determining whether to open heat exchanger valves 428. For example, whether the pressure is within operating range of a high-pressure heat exchanger, whether the flow rate at a primary or bypass pipeline is sufficient to prevent impedance of hydrocarbon production, whether power generation costs are offset by power generation needs, among other factors.

At block 508, if the wellhead fluid is at or above the vaporous phase change temperature, the master controller 402 may transmit a signal to heat exchanger valves 428 to open to a specified degree. In an example, the heat exchanger valves 428 may be may be fully opened or partially opened. The degree to which the heat exchanger valves 428 opens may depend on the temperature of the wellhead fluid, the flow rate of the wellhead fluid, and/or the pressure of the wellhead fluid.

At block 510, the master controller 402 may close wellhead fluid valves (e.g., wellhead fluid valve 1 426) to divert a portion of the flow of wellhead fluids to the high-pressure heat exchanger. The wellhead fluid valves (e.g., wellhead fluid valve 1 426) may close partially or completely, depending on various factors, such as heat exchanger flow capacity, current flow rate, current pressure, current temperature, among other factors. Once the wellhead fluid valves (e.g., wellhead fluid valve 1 426) are closed, at block 512, a working fluid pump 424 of the ORC unit may begin pumping the working fluid through the ORC loop. At block 514, the master controller 402 may determine whether electricity is being generated. If not, the master controller 402 may check if the wellhead is still active and, if the wellhead is still active, the master controller 402 may adjust the valves (e.g., wellhead fluid valve 1 426 and heat exchanger valves 428) as appropriate (e.g., increasing flow through the heat exchanger to facilitate an increase in heat transfer).

At block 516, if the wellhead fluid is lower than the vaporous phase change temperature, the master controller 402 may open or check if the wellhead fluid valves (e.g., wellhead fluid valve 1 426) are open. Further, the wellhead fluid valves may already be open to a degree and, at block 516, may open further or fully open, depending on desired wellhead fluid flow. In an example, the wellhead fluid valve (e.g., wellhead fluid valve 1 426) may be used, with or without a separate choke valve, to choke or partially choke the wellhead fluid flow. Further, once the wellhead fluid valves are open, at block 518, the master controller 402 may close the heat exchanger valves 428 fully or partially in some cases.

FIG. 6 is another flow diagram of geothermal power generation in which, when a wellhead fluid is at or above a vaporous phase change temperature, heat exchanger valves may be opened to allow wellhead fluid to flow therethrough, thereby facilitating heating of a working fluid for use in a ORC unit, according to one or more embodiment of the disclosure. The method is detailed with reference to the master controller 402 and system 400 of FIGS. 4A and 4B. Unless otherwise specified, the actions of method 600 may be completed within the master controller 402. Specifically, method 600 may be included in one or more programs, protocols, or instructions loaded into the memory of the master controller 402 and executed on the processor or one or more processors of the master controller 402. The order in which the operations are described is not intended to be construed as a limitation, and any number of the described blocks may be combined in any order and/or in parallel to implement the methods.

Blocks 602 through 610 correspond to blocks 502 through 610, as described above. Once it has been determined that the heat exchanger valves 428 should be open and after the heat exchanger valves 428 open, wellhead fluid may flow through the heat exchanger and/or the primary or bypass wellhead fluid pipe to a choke valve. The choke valve may reduce the pressure of the wellhead fluid and, thus, reduce the temperature of the wellhead fluid. At block 612, the master controller 402 may determine the reduced pressure wellhead fluid temperature at or near a condenser or heat sink valve based on a measurement from the condenser temperature sensors 422. The master controller 402 may, at block 614, determine whether the wellhead fluid is at cool enough temperatures to facilitate cooling of a working fluid flow. The working fluid may have a condensation point or a temperature at which the working fluid changes phase from a vapor to a liquid. Such a temperature may be utilized as the threshold for such determinations.

At block 616, if the temperature is cool enough, the master controller 402 may open the condenser valves 432, allowing wellhead fluid to flow through the condenser or other cooling apparatus. At block 617 the master controller 402 may transmit a signal to the working fluid pump 424 to start or begin pumping working fluid through an ORC loop. In another example, at block 619, if the temperature of the working fluid is not cool enough to facilitate cooling of the working fluid to any degree, the master controller 402 may close the condenser valves 432. In another example, the master controller 402 may determine the temperature of the reduced pressure wellhead fluid flow and whether the temperature of the reduced pressure wellhead fluid flow, in conjunction with a primary or secondary cooler, may cool the working fluid to a point. The master controller 402, in such examples, may consider the temperature of the working fluid entering the condenser and the temperature of the reduced pressure wellhead fluid flow at or near the condenser valve 432.

As noted and described above, the master controller 402 may, at block 618, determine whether electric power is generated. In another example, if the wellhead temperature is not high enough to produce geothermal power, the master controller 402 may, at block 620, open the wellhead fluid valves. At block 622, the master controller 402 may close, if the heat exchanger valves 428 are open, the heat exchanger valves 428. Finally, at block 624, the master controller 402 may close condenser valves 432.

FIG. 7A is a flow diagram of geothermal power generation in which, when a working fluid or ORC fluid is at or above a vaporous phase change temperature threshold, heat exchanger valves may remain open to allow wellhead fluid to flow therethrough, thereby facilitating heating of the working fluid or ORC fluid for use in an ORC unit, according to one or more embodiment of the disclosure. The method is detailed with reference to the master controller 402 and system 400 of FIGS. 4A and 4B. Unless otherwise specified, the actions of method 700 may be completed within the master controller 402. Specifically, method 700 may be included in one or more programs, protocols, or instructions loaded into the memory of the master controller 402 and executed on the processor or one or more processors of the master controller 402. The order in which the operations are described is not intended to be construed as a limitation, and any number of the described blocks may be combined in any order and/or in parallel to implement the methods.

At block 702, the master controller 702 may determine whether the wellhead is active. Such a determination may be made based on sensors located at or near the wellhead, e.g., a pressure sensor indicating a pressure or a flow meter indicating a flow of a wellhead fluid or hydrocarbon stream from the wellhead. In other examples, a user may indicate, via the user interface 436, that the wellhead is active. If the wellhead is not active, the master controller 402 may wait for a specified period of time and make such a determination after the specified period of time. In an example, the master controller 402 may continuously check for wellhead activity.

At block 704, in response to wellhead activity or during hydrocarbon production, the master controller 402 may open heat exchanger valves 428. At block 706, the master controller 402 may close wellhead fluid valve 1 426, at least partially. At block 708, when the heat exchanger valves 428 is open and wellhead fluid valve 1 426 is fully or partially closed, working fluid or ORC fluid may be pumped through the ORC unit.

At block 710, the master controller 402 may measure the temperature of the working fluid or ORC fluid. At block 712, the master controller 402 may determine whether the wellhead fluid is at or above a vaporous phase change temperature threshold. In such examples, the vaporous phase change may include when the working fluid or ORC fluid changes from a liquid to a vapor or gas. For example, for pentafluoropropane the vaporous phase change temperature or boiling point may be 15.14 degrees Celsius. In another example, other factors may be taken into account when determining whether to maintain an open percentage of the heat exchanger valves 428. For example, whether the pressure is within operating range of a high-pressure heat exchanger, whether the flow rate at a primary or bypass pipeline is sufficient to prevent impedance of hydrocarbon production, whether power generation costs are offset by power generation needs, among other factors.

At block 712, if the working fluid or ORC fluid is at or above the vaporous phase change temperature, the master controller 402 may determine whether electricity is generated at the ORC unit. If electricity is not generated, the master controller 402 may check, at block 702, whether the wellhead is active and perform the operations of method 700 again.

If the working fluid or ORC fluid, at block 712 is not at a vaporous phase change temperature, then, at block 714, the master controller 402 may first determine whether a first specified period of time has lapsed. The first period of time may be period of time of sufficient length to determine whether or not the working fluid or ORC fluid may reach a vaporous phase change state. Such a first specified period of time may be about an hour or more, two hours, three hours, four hours, or some other length of time during wellhead activity.

If the first specified period of time has not lapsed, at block 716, the master controller 402 may wait a second specified period of time before measuring the temperature of the working fluid or ORC fluid The second specified period of time may be less than the first specified period of time.

If the first specified period of time has lapsed, then the master controller 402 may have determined that, based on the temperature of the working fluid or ORC fluid, that the wellhead fluid may not reach temperatures sufficient to cause a vaporous phase change of the working fluid or ORC fluid. As such, at block 718, the master controller may close the open wellhead fluid valves and, at block 720, close the heat exchanger valves 428.

FIG. 7B is another flow diagram of geothermal power generation in which, when a working fluid or ORC fluid is at or above a vaporous phase change temperature threshold, heat exchanger valves may remain open to allow wellhead fluid to flow therethrough, thereby facilitating heating of the working fluid or ORC fluid for use in an ORC unit, according to one or more embodiment of the disclosure. The method is detailed with reference to the master controller 402 and system 400 of FIGS. 4A and 4B. Unless otherwise specified, the actions of method 701 may be completed within the master controller 402. Specifically, method 701 may be included in one or more programs, protocols, or instructions loaded into the memory of the master controller 402 and executed on the processor or one or more processors of the master controller 402. The order in which the operations are described is not intended to be construed as a limitation, and any number of the described blocks may be combined in any order and/or in parallel to implement the methods.

Blocks for FIG. 7B may perform the same functions as described for blocks of FIG. 7A. As such, those blocks include the same numbers, such as block 702 through block 722. In addition to those operations, at block 724 the master controller 402 may check whether the heat exchanger vales may be open. If they are not the master controller 402 may open the heat exchanger valves and close, at least partially, the wellhead fluid valves. If the heat exchanger valves are open, the master controller 402 may not change or adjust any of the valves open percentage, but rather continue to or start pumping the working fluid or ORC unit through the ORC unit.

In addition, after the master controller 402 closes the heat exchanger valves at block 720, the master controller 402 may determine, at block 726, the wellhead fluid temperature at the heat exchanger. At block 728, the master controller may determine whether the wellhead fluid is at a vaporous phase change temperature of the working fluid or ORC fluid. If the wellhead fluid temperature is less than such a value, the master controller 402 may wait and measure the temperature again after a period of time. If the wellhead fluid temperature is greater than or equal to such a value, the master controller 402 may perform the operations of method 701 starting at block 724 again.

FIG. 8 is a flow diagram of geothermal power generation in which a working fluid flow is determined based on a preselected electrical power output threshold, according to one or more embodiment of the disclosure. The method is detailed with reference to the master controller 402 and system 400 of FIGS. 4A and 4B. Unless otherwise specified, the actions of method 800 may be completed within the master controller 402. Specifically, method 800 may be included in one or more programs, protocols, or instructions loaded into the memory of the master controller 402 and executed on the processor or one or more processors of the master controller 402. The order in which the operations are described is not intended to be construed as a limitation, and any number of the described blocks may be combined in any order and/or in parallel to implement the methods.

At block 802, each of one or more heat exchangers may be connected to one or more wellhead fluid lines. Each of the one or more wellhead fluid lines may correspond to a wellhead. At block 804, an ORC unit may be connected to the one or more heat exchangers. In another example, the system 400 may include one or more ORC units and each of the one or more ORC units may connect to one or more heat exchangers or two or more heat exchangers.

At block 806, heat exchanger valves positioned between the one or more heat exchangers and the one or more wellhead fluid lines may be opened. Once opened, the heat exchanger valves may allow for continuous diversion of the flow of wellhead fluid through the heat exchanger. The flow of wellhead fluid through the heat exchanger may facilitate transfer of heat from the flow of wellhead fluid to a flow of working fluid or intermediate working fluid.

At block 808, ORC unit valves may be opened. The ORC unit valves may initially be fully opened or partially opened. The ORC unit valves, when open, may allow for working fluid from each of the heat exchangers to flow into the ORC unit. Each working fluid flow may be combined and may pass through the ORC unit.

At block 810, the master controller 402 may determine one or more operating conditions of the ORC unit and/or the system 400. The one or more operating conditions may include the flow rate and/or pressure of working fluid flowing through each of the one or more heat exchangers, the flow rate and/or pressure of wellhead fluid flowing through each of the one or more heat exchangers or at any other point downstream of the wellhead, the temperature of the working fluid in each of the one or more heat exchangers, the temperature of wellhead fluid at each of the one or more heat exchangers, the temperature of the combined working fluid flow at the ORC unit, the electrical power output from the ORC unit, and/or the open position of each of the valves included in the system 400.

At block 812, based on the determined operating conditions, the master controller 402 may determine an optimal or efficient working fluid flow of the ORC unit. The optimal or efficient working fluid flow may depend on the temperature of the combined working fluid flowing to the ORC unit. The other operating conditions, described above, may be utilized to determine the optimal or efficient working fluid flow. The optimal or efficient working fluid flow may comprise the combined flow of working fluid flowing into the ORC unit to thereby produce a maximum amount of electrical power possible or to enable the ORC unit to meet a preselected electrical power output threshold. The optimal or efficient working fluid flow may be at a temperature sufficient to produce such an amount of electrical power (e.g., a temperature greater than or equal to the boiling point of the working fluid within the ORC unit). The optimal or efficient working fluid flow may be indicated by the master controller 402 as one or more open positions for each of the ORC unit valves and/or heat exchanger valves.

At block 814, the master controller 402 may, based on a determined optimal or efficient working fluid flow, determine whether to adjust the one or more ORC unit valves. Other valves within the system 400 may be adjusted based on the optimal or efficient working fluid flow, such as one or more heat exchanger valves and/or one or more wellhead fluid valves. If it is determined that the ORC unit valves or any other valves are to be adjusted, the master controller 402, at block 816, may transmit a signal to the valve to be adjusted indicating a new open position or closed position for the valve to adjust to. After the signal is transmitted, the valve may automatically adjust to the position indicated. If the valve is not to be adjusted or after the valves have been adjusted, the master controller 402 may determine operating conditions again. In an example, the master controller 402 may wait for a period of time, allowing the system to adjust to the new temperatures and flow rates or to reach equilibrium, prior to determining the operating conditions.

FIG. 9A, FIG. 9B, FIG. 9C, FIG. 9D, and FIG. 9E are block diagrams illustrating novel implementations of one or more geothermal power generation enabled wells to provide electrical power to one or more of in-field equipment, equipment at one of the other wells, energy storage devices, and the grid power structure, according to one or more embodiment of the disclosure. As illustrated in FIG. 9A, various wells 902A, 902B, up to 902N may be positioned in proximity to one another. For example, one well (e.g., well A 902A may be located at a distance of over about 1 mile, about 5 miles, about 10 miles, about 25 miles, or more to another well (e.g., well B 902B or well N 902N). Each well 902A, 902B, 902N may include various in-field equipment 910A, 910B, 910N. Each well 902A, 902B, 902N may include one or more wellheads 904A, 904B, 904N. Each wellhead 904A, 904B, 904N may connect to a high-pressure heat exchanger 906A, 906B, 906N and the high-pressure heat exchanger 906A, 906B, 906N may connect to ORC equipment 908A, 908B, 908N. The ORC equipment 908A, 908B, 908N may generate electrical power. The electrical power may be provided to the in-field equipment 910A, 910B, 910N. A surplus of electrical power may be provided to an energy storage device 920A, 920B, 920N. The ORC equipment 908A, 908B, 908N may also transmit electrical power energy to other wells, energy storage devices, or to a grid power structure 912.

As noted and as illustrated in FIG. 9B, the high-pressure heat exchanger N 906N may connect to one or more wellheads 904A, 904B, 904N. For example, a well N 902 may include 1, 2, 3, or more wellheads (e.g., wellhead A 904A, wellhead B 904B, and/or up to wellhead N 904N). All of the wellheads 904A, 904B, 904N may connect to one high pressure heat exchanger N 906N. In another example, a well N 902N may include one or more high-pressure heat exchangers, as illustrated in FIG. 9D and FIG. 9E. In such examples, the wellheads 904A, 904B, 904N may connect to one or more of the high-pressure heat exchangers.

As described and as illustrated in FIG. 9C, the well N 902N may include one or more wellheads (e.g., wellhead A 904A, wellhead B 904B, and/or up to wellhead N 904N), one or more sets of ORC equipment (e.g., ORC equipment A 908A, ORC equipment B 908B, and/or up to ORC equipment N 908N), and one or more sets of in-field equipment (e.g., in-field equipment A 910A, in-field equipment B 910B, and/or up to in-field equipment N 910N). As noted, a well N 902N may include one high-pressure heat exchanger, as illustrated in in FIG. 9D and FIG. 9E. The well 902 may further include additional high-pressure heat exchangers 906.

As illustrated in FIGS. 9D and 9E, a well N 902N may include one or more wellheads (e.g., wellhead A 904A, wellhead B 904B, and/or up to wellhead N 904N). Each of the one or more wellheads 904A, 904B, 904N may correspond to a high-pressure heat exchanger (e.g., heat exchanger A 906A, heat exchanger B 906B, and/or up to heat exchanger N 906N). In other examples, two or more high-pressure heat exchangers may correspond to a particular wellhead, while in other examples, two or more wellheads may correspond to a high-pressure heat exchanger. Further, a well N 902N may include one ORC equipment A 908A or unit, as illustrated in FIG. 9D. A well N 902N may include two ORC equipment (e.g., ORC equipment A 908A and ORC equipment B 908B) or units or, in some cases, more. In such examples, each ORC equipment 908A, 908B may connect to each of the high-pressure heat exchangers 906A, 906B, 906N. As wellhead fluid flows from a wellhead 904A, 904B, 904N, the temperature and pressure may vary based on a number of factors (e.g., production, type of fluids, distance from the high-pressure heat exchanger, among other factors).

As such, a working fluid of a particular high-pressure heat exchanger 906A, 906B, 906N may be heated to a degree sufficient, insufficient, or more than sufficient to cause the working fluid of the ORC equipment 908A, 908B to exhibit a vaporous phase change. Since the temperature of the wellhead fluid varies, a controller (e.g., controller 916A, 916B, up to 916N or master controller 918, as illustrated in FIG. 9F) may determine the temperature of working fluid at each high-pressure heat exchanger 906 and determine the most efficient and/or optimal combination to be utilized for generating the most electrical power or for generating an amount of electrical power to meet a preselected electrical power output threshold at the ORC equipment 908A, 908B. The electrical power output by the ORC equipment 908A, 908B may be measured by, for example, an electrical power meter or other device suitable to determine electrical power output. The controller may also determine the temperature of the combination of working fluid or intermediate working fluid entering the ORC equipment 908A, 908B, via, for example, one or more temperature sensors positioned at or near an inlet of the ORC equipment 908A, 90B. The inlet may allow working fluid or intermediate working fluid to flow into the ORC equipment 908A, 908B. The controller may determine the most efficient and/or optimal combination or amount of working fluid or intermediate working fluid from the one or more high-pressure heat exchangers 906A, 906B, 906N based on a variety of factors noted above. For example, the most efficient and/or optimal combination or amount may be based on wellhead fluid temperature from each of the one or more wellheads 904A, 904B, 904N, the working fluid or intermediate working fluid temperature at each of the high-pressure heat exchangers 906A, 906B, 906N, and/or electrical power output (e.g., a measurement indicative of the electrical power generated) by the ORC equipment 908A, 908B. Other factors may include flow rate and pressure of each of the high-pressure heat exchangers 906A, 906B, 906N, current open positions high-pressure heat exchanger valves, and/or current open positions of other valves included at the well N 902N.

For example, if high-pressure heat exchanger A 906A includes a working fluid at a temperature slightly less than a temperature to cause vaporous phase change, then valves providing working fluid or intermediate working fluid from the high-pressure heat exchanger A 906A to the ORC equipment 908A, 908B may be closed. In another example, if high-pressure heat exchanger B 906B is providing working fluid at a temperature well above a temperature to cause vaporous phase change, then valves providing working fluid or intermediate working fluid from high-pressure heat exchanger B 906B to ORC equipment A 908A and/or to ORC equipment B 908B may be adjusted to positions such that a greater portion of the working fluid or intermediate working fluid is transported to ORC equipment A 908A and/or to ORC equipment B 908B.

In yet another example, all valves for allowing flow of working fluid or intermediate working fluid to the ORC equipment A 908A and/or ORC equipment B 908B may be, at least, in a partially open position. The temperature of the wellhead fluid and/or working fluid of each heat exchanger 906A, 906B, 906N may be determined or measured. Further, the electrical power output of the ORC equipment A 908A and/or ORC equipment B 908B may be determined. The positions of each valve for allowing flow of working fluid or intermediate working fluid to the ORC equipment A 908A and/or ORC equipment B 908B may be adjusted to different partially open positions, fully opened positions, or fully closed positions. Such valve adjustments may be based on maximization of the resultant temperature and heat delivered to the ORC equipment A 908A and/or ORC equipment B 908B once the combined working fluid flows into the ORC equipment 908 A 908A and/or ORC equipment B 908B. The valve adjustments may be based on, rather than or in addition to other factors, the maximization of the electrical power output from the ORC equipment A 908A and/or ORC equipment B 908B. Valve adjustments may further be based on wellhead fluid temperature and/or some combination of the factors described herein.

As noted and described above and as illustrated in FIG. 9F, a controller (e.g., controller A 916A, controller B 916B, and/or up to controller N 916N) may be included at one or more of the wells 902A, 902B, 902N. The controller 916A, 916B, 916N may control and monitor various aspects of the well 902A, 902B, 902N. The controller 916A, 916B, 916N of each well 902A, 902B, 902N may connect to a master controller 918, the master controller 918 may control the operations of the ORC equipment 908A, 908B, 908N, as well as other equipment (e.g., valves and/or pumps) at each of the wells 902A, 902B, 902N. As described above and illustrated in FIG. 9G, the master controller 918 may connect to one or more wellheads 904A, 904B, 904N. The ORC enabled wells 902A, 902B, 902N may provide power to one or more of in-field equipment at the ORC enabled well 902A, 902B, 902N, to an energy storage device, and/or a grid structure device (see 912).

This application is a continuation of U.S. application Ser. No. 18/149,316, filed Jan. 3, 2023, titled “SYSTEMS FOR GENERATING GEOTHERMAL POWER IN AN ORGANIC RANKINE CYCLE OPERATION DURING HYDROCARBON PRODUCTION BASED ON WELLHEAD FLUID TEMPERATURE”, which is a continuation of U.S. application Ser. No. 17/650,811, filed Feb. 11, 2022, titled “SYSTEMS FOR GENERATING GEOTHERMAL POWER IN AN ORGANIC RANKINE CYCLE OPERATION DURING HYDROCARBON PRODUCTION BASED ON WELLHEAD FLUID TEMPERATURE”, now U.S. Pat. No. 11,578,706, issued Feb. 14, 2023, which is a continuation of U.S. application Ser. No. 17/305,298, filed Jul. 2, 2021, titled “SYSTEMS FOR GENERATING GEOTHERMAL POWER IN AN ORGANIC RANKINE CYCLE OPERATION DURING HYDROCARBON PRODUCTION BASED ON WELLHEAD FLUID TEMPERATURE”, now U.S. Pat. No. 11,280,322, issued Mar. 22, 2022, which claims priority to and the benefit of U.S. Provisional Application No. 63/200,908, filed Apr. 2, 2021, titled “SYSTEMS AND METHODS FOR GENERATING GEOTHERMAL POWER DURING HYDROCARBON PRODUCTION,” the entire disclosures of all of which are incorporated herein by reference.

In the drawings and specification, several embodiments of systems and methods to provide geothermal power in the vicinity of a wellhead during hydrocarbon production have been disclosed, and although specific terms are employed, the terms are used in a descriptive sense only and not for purposes of limitation. Embodiments of systems and methods have been described in considerable detail with specific reference to the illustrated embodiments. However, it will be apparent that various modifications and changes can be made within the spirit and scope of the embodiments of systems and methods as described in the foregoing specification, and such modifications and changes are to be considered equivalents and part of this disclosure. 

What is claimed is:
 1. A system to generate electrical power, the system comprising: a valve positioned to divert wellhead fluid from a wellhead; a heat exchanger including (a) a first fluid path to receive the wellhead fluid from the valve and (b) a second fluid path to receive a working fluid, the heat exchanger positioned to transfer heat from the wellhead fluid to the working fluid; a recycle unit, including a generator, a condenser, and a pump, positioned so that a flow of the working fluid from the second fluid path causes the generator to generate electrical power during operation when the condenser is positioned to cool the working fluid of the heat exchanger and the pump is positioned to transport the working fluid from the condenser toward the second fluid path of the heat exchanger; a first valve operatively positioned to reduce a pressure and temperature of the wellhead fluid from the heat exchanger; and a second valve positioned to divert at least some of wellhead fluid from the choke valve to the condenser.
 2. The system of claim 1, further comprising a third valve positioned to adjust flow of wellhead fluid from the wellhead, during operation, based on the diversion of the flow of wellhead fluid to the heat exchanger.
 3. The system of claim 2, further comprising a fourth valve positioned to control flow of wellhead fluid from the first valve, during operation, based on a percentage that the condenser valve is in an open position.
 4. The system of claim 1, wherein the recycle unit comprises one or more ORC units connected to the heat exchanger, the one or more ORC units including the at least the generator, the condenser, and the pump, and the system further comprising another one or more ORC units connected to the recycle unit.
 5. The system of claim 1, wherein the recycle unit comprises an ORC unit, the ORC unit including a working fluid reservoir to store working fluid flowing from the condenser.
 6. The system of claim 1, wherein the first fluid path of the heat exchanger is configured to withstand corrosion caused by the wellhead fluid, and wherein the heat exchanger includes a vibration induction device to reduce scaling caused by the flow of the wellhead fluid.
 7. A system for generating geothermal power in the vicinity of a wellhead, thereby to supply electrical power to one or more of in-field equipment, a grid power structure, and energy storage devices, the system comprising: a first pipe in fluid communication with the wellhead, thereby to transport wellhead fluid therethrough; one or more valves positioned to control flow of wellhead fluid; a heat exchanger positioned to accept the flow of wellhead fluid when the one or more valves is open, the heat exchanger including a first opening and a second opening connected via a first fluid path and a third opening and a fourth opening connected via a second fluid path, the first fluid path and the second fluid path to facilitate heat transfer from the flow of wellhead fluid to a working fluid during operation, thereby to cause the working fluid to change fluid phases, the flow of wellhead fluid flowing into the first opening of the heat exchanger through the first fluid path and to the second opening of the heat exchanger, and a flow of the working fluid flowing into the third opening through the second fluid path and out of the fourth opening; a second pipe connected to and in fluid communication with the one or more valves; a choke valve in fluid communication with the second pipe and positioned to reduce a pressure of the flow of wellhead fluid, thereby to reduce a temperature of the wellhead fluid; a condenser valve in fluid communication with the choke valve, the condenser valve positioned to control flow of wellhead fluid based on whether the one or more valves is in an open position; a generator in fluid communication with the fourth opening of the heat exchanger, the working fluid flowing from the fourth opening to the generator, thereby to cause the generator to generate electrical power during operation; and a condenser including a first opening and second opening connected via a first fluid condenser path and a third opening and fourth opening connected via a second fluid condenser path, the first opening connected to the condenser valve, the second opening connected to an output pipe, and the third opening connected to receive the working fluid, the first fluid condenser path and the second fluid condenser path positioned to facilitate heat transfer from the working fluid to the flow of wellhead fluid.
 8. The system of claim 7, wherein the working fluid includes one or more of pentafluoropropane, carbon dioxide, ammonia and water mixtures, tetrafluoroethane, isobutene, propane, pentane, perfluorocarbons, or other hydrocarbons.
 9. The system of claim 8, wherein the generator includes a rotation mechanism, a stator, and rotor, the rotor connected to the rotation mechanism, the rotor to rotate as the rotation mechanism spins via the flow of working fluid.
 10. The system of claim 9, wherein the rotation mechanism includes one of a turbine expander, a positive displacement expander, or a twin-screw expander.
 11. The system of claim 10, wherein the rotation mechanism connects to the rotor via one of a transmission and gearbox.
 12. The system of claim 8, further comprising a heat exchanger valve, and wherein when the heat exchanger valve is in an open position, at least a portion of the flow of wellhead fluid is diverted from a first valve of the one or more valves.
 13. The system of claim 7, wherein the working fluid changes phase from liquid to vapor when the temperature of the wellhead fluid comprises a temperature from greater than or equal to about 50 degrees Celsius, and wherein the heat exchanger is configured to withstand pressures up to about 15,000 pounds per square inch (PSI).
 14. The system of claim 7, further comprising an expander through which the working fluid flows and a regenerator, and wherein, after the working fluid flows through the expander, the working fluid flows through the regenerator and, after the working fluid flows through the condenser, the working fluid flows through the regenerator, the regenerator pre-heating the working fluid from the condenser via heat of the working fluid from the generator during operation.
 15. The system of claim 7, wherein the heat exchanger includes a pressure relief valve to release pressure in the event that the heat exchanger exhibits a pressure exceeding a maximum pressure rating of the heat exchanger, and wherein the choke valve reduces the pressure of the flow of wellhead fluid to less than or equal to about 1,500 PSI so that the reduction of pressure of the flow of wellhead fluid reduces the temperature of the wellhead fluid to less than or equal to about 50 degrees Celsius.
 16. The system of claim 7, wherein the wellhead fluid includes one or more of a liquid or a gas, and wherein the wellhead fluid includes hydrocarbons.
 17. The system of claim 7, wherein the wellhead fluid further includes a mixture of hydrocarbons and one or more of (a) water or (b) other chemical residuals.
 18. The system of claim 7, wherein the working fluid is heated in the heat exchanger to the point of evaporation of the working fluid, and wherein the working fluid is heated in the heat exchanger to saturation temperature under high-pressure.
 19. The system of claim 7, wherein the working fluid includes a mixture of two or more fluids, each of the two or more fluids including different vaporous phase change points and different condensation points.
 20. A system for generating electrical power, the system comprising: a first pipe in fluid communication with a wellhead so as to receive a wellhead fluid from the wellhead; a valve having in fluid communication with the first pipe; a heat exchanger positioned to receive the wellhead fluid downstream of the valve, the heat exchanger including a wellhead fluid path to receive the wellhead fluid therethrough and a working fluid path to receive a working fluid therethrough, the wellhead fluid path and the working fluid path to facilitate heat transfer from the wellhead fluid to the working fluid during operation; a second pipe in fluid communication with the second end of the valve; a choke valve in fluid communication with the second pipe to reduce a pressure and a temperature of the wellhead fluid; a condenser valve in fluid communication with the choke valve to control a flow rate of the wellhead fluid therethrough based on whether the valve is in an open position; a generator positioned such that a flow of the working fluid from the working fluid path causes the generator to generate electrical power during operation; and a condenser including a first fluid condenser path and a second fluid condenser path, the first fluid condenser path connected to the condenser valve so as to receive the wellhead fluid downstream of the condenser valve, the second fluid condenser path connected to the heat exchanger so as to receive the working fluid downstream of the heat exchanger, the first fluid condenser path and the second fluid condenser path to facilitate heat transfer from the working fluid to the wellhead fluid during operation.
 21. The system of claim 20, wherein the working fluid includes one or more of pentafluoropropane, carbon dioxide, ammonia and water mixtures, tetrafluoroethane, isobutene, propane, pentane, perfluorocarbons, or other hydrocarbons.
 22. The system of claim 20, wherein the working fluid changes phase from liquid to vapor when the temperature of the wellhead fluid comprises a temperature greater than or equal to about 50 degrees Celsius, and wherein the heat exchanger is configured to withstand pressures up to about 15,000 pounds per square inch (PSI).
 23. The system of claim 20, further comprising an expander through which the working fluid flows and a regenerator, and wherein, after the working fluid flows through the expander, the working fluid flows through the regenerator and, after the working fluid flows through the condenser, the working fluid flows through the regenerator, the regenerator pre-heating the working fluid from the condenser via heat of the working fluid from the generator during operation.
 24. The system of claim 20, wherein the wellhead fluid includes one or more of a liquid or a gas, and wherein the wellhead fluid includes hydrocarbons.
 25. The system of claim 20, wherein the working fluid is heated in the heat exchanger to the point of evaporation of the working fluid during operation, and wherein the working fluid is heated in the heat exchanger to saturation temperature under high-pressure during operation. 